The present invention relates to drilling subterranean well bores of the type commonly used for oil or gas wells. More particularly, this invention relates to an improved method and system for maintaining bottom hole hydrostatic pressure while making a drill pipe connection. The methods and system of this invention facilitate improving hydrostatic control of a well bore while drilling with a reduced equivalent circulating density (xe2x80x9cECDxe2x80x9d).
Drilling subterranean wells typically requires circulating a drilling fluid (xe2x80x9cmudxe2x80x9d) through a drilling fluid circulation system (xe2x80x9csystemxe2x80x9d). The circulation system may include a drilling rig located substantially at the surface. The drilling fluid may be pumped by a mud pump through the interior of a drill string, through a drill bit and back to the surface of the well bore through the annulus between the well bore and the drill pipe. When the circulated drilling fluid arrives back at the surface, cuttings and other solid contaminants are commonly separated from the circulated drilling fluid such that substantially xe2x80x9cuncontaminatedxe2x80x9d drilling fluid may be recirculated.
A primary function of drilling fluid is to provide hydrostatic well control. Traditional overbalanced drilling techniques practice maintaining a hydrostatic pressure on the formation equal to or slightly overbalanced with respect to formation pore pressure. In underbalanced drilling techniques, hydrostatic pressure is maintained at least slightly lower than formation pore pressure by the drilling fluid supplemented with surface well control equipment providing the well control.
As well depth increases, a change in density of the drilling fluid translates into a more pronounced corresponding change in hydrostatic pressure at the bottom of the well bore. Certain formations penetrated by the well bore at deeper depths may not tolerate significant changes in hydrostatic pressure. Hydrostatic pressure changes may result in either a formation fluid influx into the wellbore (a xe2x80x9ckickxe2x80x9d) or in the drilling fluid invading or being lost into the formation (xe2x80x9clost circulationxe2x80x9d). As a result, density control may become more critical as well depth increases.
Drilling fluid is circulated through the fluid system by applying a circulating pressure to the fluid at the surface to pump the fluid through the system. As drilling fluid is circulated through the system, the fluid encounters a series of friction related pressure drops, the sum of which may be roughly equal to the pump pressure required to circulate the fluid (xe2x80x9ccirculating pressurexe2x80x9d). The circulating friction is primarily due to the dynamic interaction between the fluid and the particular conduits through which the fluid is circulating. The mud pump and bottom hole circulating pressure typically remains substantially constant for a particular set of operating parameters.
While circulating drilling fluid, such as when drilling, the bottom hole hydrostatic pressure exerted on the formation is increased above a non-circulating (xe2x80x9cstaticxe2x80x9d) hydrostatic pressure by the amount of friction pressure in the well bore annulus. The resulting bottom hole pressure applied to the formation while circulating drilling fluid may be calculated in terms of an equivalent fluid density, commonly called an equivalent circulating density (xe2x80x9cECDxe2x80x9d).
When a drill pipe connection is required, circulation is typically terminated for a few minutes while the connection is being performed. When circulation is terminated, the bottom hole hydrostatic pressure on the formation is reduced by approximately the amount of pressure equal to the friction losses in the well bore annulus between the bit and the surface. To maintain well control while circulation is terminated, the drilling fluid density is typically sufficiently high to maintain hydrostatic control under the static conditions.
Another primary function of drilling fluid is to carry cuttings and solid materials, such as weighting agents, to the surface. To prevent cuttings and solid material entrained within the drilling fluid from falling down hole and sticking the drill pipe when circulation is terminated, one or more agents may be added to the drilling fluid to provide a xe2x80x9cgelxe2x80x9d strength to the fluid and/or increase fluid viscosity. The gel strength of a drilling fluid is a measure of the ability of the fluid to either suspend cuttings in the fluid or the degree to which the fluid may retard the rate at which the cuttings fall back. When movement of a drilling fluid having some degree of gel strength is stopped, the fluid may require the application of an initial pressure (stress) in excess of a minimum threshold pressure to initiate movement (shear) of the fluid. Such fluid may be referred to as a xe2x80x9cnon-Neutonianxe2x80x9d or xe2x80x9cBingham plasticxe2x80x9d fluid. The minimum stress required to initiate movement of a Bingham plastic fluid may be referred to as the Bingham yield pressure. Bingham plastic fluids may also require a higher circulation pressure and may generate higher friction pressure drops, than neutonian fluids, thereby resulting in an increased ECD for the plastic fluids.
When the drill pipe connection is completed, the mud pumps are typically re-engaged to regain circulation. To initiate or xe2x80x9cbreakxe2x80x9d circulation throughout the system, a startup circulation pressure may be applied to the fluid by the mud pumps and may be transmitted through the circulation system including the bottom hole formations. In certain well bore conditions, the magnitude of the circulation startup pressure (xe2x80x9cstartup ECDxe2x80x9d) required to reach the Bingham yield pressure may exceed the circulating ECD pressure attributable in part to friction pressure as the fluid begins to circulate. Thereby, initiation of circulation of a non-neutonian fluid may have to be conducted slowly to avoid the startup ECD exceeding the ECD. Care may be required during startup and during circulation to avoid the ECD exceeding either or both the pore pressure in the formation and the fracture pressure of the formation matrix, which may result in drilling fluid circulation being partially or completely lost to the formation. Loss of circulation may result in loss of well control, loss of expensive drilling fluids, stuck drill pipe, or other related adverse consequences. Thereby, the startup ECD and the circulating ECD are both disadvantages of prior art.
As circulation is established and drill pipe rotation is commenced, the circulating pressure may reduce to the ECD pressure. The changes in circulation pressure and the corresponding changing hydrostatic pressure exerted upon the formation results in reduced control of hydrostatic pressure exerted upon the formation. In overbalanced drilling, the applied hydrostatic pressure also may be substantially higher than the minimum hydrostatic pressure that may otherwise be required to maintain well control. Those skilled in the industry may appreciate that increased drilling fluid density and hydrostatic pressure may result in reductions in rate of penetration (xe2x80x9cROPxe2x80x9d) by the drill bit, further resulting in increase time and well costs. The hydrostatic pressure fluctuations, the complex determinations of actual circulating bottom hole pressure, the increased fluid density, and the resultant decreased ROP are also disadvantages of the prior art.
The disadvantages of prior art are overcome by the present invention. An improved method and system for more accurately controlling well bore hydrostatic pressure and reducing the startup ECD and the ECD are described herein.
This invention provides methods and systems for drilling a well bore through a subterranean formation whereby the hydrostatic pressure exerted upon the formation by the drilling fluid (xe2x80x9cmudxe2x80x9d) may be maintained substantially the same regardless of whether the drilling fluid is or is not being circulated. The bottom hole pressure exerted on a formation during periods of drilling fluid circulation may be the equivalent circulating density (xe2x80x9cECDxe2x80x9d). The ECD may be at least partially dependent upon circulation rate and fluid density. The methods and systems of this invention may facilitate maintaining the ECD when circulation is interrupted, such as when a joint of drill pipe is added to or removed from the drill string.
An ECD may be determined at substantially any point in the well bore. The ECD may be maintained when not circulating by trapping pressure within the well bore. The magnitude of pressure trapped in the well bore may be substantially same as the friction pressure drops in the well bore annulus during circulation and/or the amount of pressure, if any, required to re-initiate circulation after circulation has ceased.
The well bore may be enclosed by one or more conventional well bore sealing members. The well bore may be at least partially enclosed by activating an annular sealing device, such as an annular rotating blowout preventer. In addition, a choke or valve member may be provided on the mud return line and a check valve may be provided in the through bore of the drill string, such that an interior of the well bore may be enclosed.
To trap pressure within the wellbore, a rotating annular BOP may be closed on the drill pipe while circulating drilling fluid through the drill string and well bore annulus and out the mud return line to a mud receptacle. In addition, the mud return line choke may be controllably closed while the circulation rate is controllably reduced, such that fluid pressure is controllably applied to and trapped within the well bore. Similarly, the mud pump (or a booster pump in a mud pump system including a plurality of pumps fluidly in parallel), may be used to control back pressure in the well. A pressure sensing apparatus may monitor the magnitude of the pressure trapped in the annulus. A programmable controller may coordinate and control the circulation rate, the mud return line choke and the well bore fluid pressure such that as the circulation rate is reduced to substantially zero the ECD is maintained in the well bore.
A drill pipe connection may be made up or broke out, or other work may be performed during the period in which circulation is interrupted. To compensate for any pressure losses within the well bore, a booster pump, a booster line, and a booster port may be provided to pump additional fluid into the well bore annulus to maintain a desired pressure within the well bore. To re-initiate circulation, the mud return line choke may be activated to release a portion of the fluid pressure from within the well bore and the mud pumps may be activated to controllably increase the circulation rate until a desired circulation rate is established and the choke may be fully opened. In either decreasing circulation rate to shut the well in or increasing circulation rate to re-establish a desired circulation rate, the rate of change of rate of circulation may be relatively slow or small, such that dynamic force effects may be minimized.
It is an object of this invention to provide methods and systems for maintaining a reduced ECD on a formation while drilling a well bore through the formation. This invention provides methods and systems for maintaining hydrostatic control of a wellbore in either a dynamic or static fluid circulation condition. In a dynamic circulation condition, the ECD may be substantially the same as the static non-circulating well bore hydrostatic pressure, which may be less than or equal to the circulating ECD.
It is also an object of this invention to provide methods and systems for adding a joint of drill pipe to or removing a joint of drill pipe from a drill string, while substantially simultaneously maintaining well control with a hydrostatic pressure which is less than or equal to the ECD pressure.
It is a feature of this invention that pressure may be trapped and maintained within the well bore as the drilling fluid circulation rate is reduced to substantially zero. Such trapped pressure may thereby also maintain hydrostatic well control with a drilling fluid having a lower fluid density than may otherwise by required to maintain well control.
It is another feature of this invention that initiation of drilling fluid circulation may be at least partially facilitated by the release of a portion of the trapped pressure from the well bore annulus, prior to activating the mud pump. The pressure release may act upon the drilling fluid in the well bore annulus to cause a portion of the fluid to break its gel condition and begin moving, thereby reducing the amount of pressure that may be required to be applied to the drilling fluid by the mud pumped to otherwise initiate circulation. Thereby the startup ECD may be reduced.
It is also a feature of this invention that the drill string may be rotated while pressure is being trapped, being release from or maintained within the well bore. In addition, drill string rotation may be selectively interrupted or altered.
It a further feature of this invention that a joint of drill pipe may be added to or removed from the drill string while the drill string is being rotated.
Another feature of this invention is that rates of penetration by the drill bit may be realized, due to the use of the lower density drilling fluid, while maintaining well control.
It is an advantage of this invention that this invention may be practiced by utilizing commonly used and/or available components, familiar to the well bore drilling industry. A rotating annular BOP, an adjustable choke and a drill string check valve may each be included.
It is also an advantage of this invention that a drilling fluid may be used to maintain hydrostatic control of a well bore, which includes a density that may be lower than the density of a drilling fluid that may otherwise be required to maintain well control.
It is a further advantage of this invention that formation drilling fluid invasion and formation fracturing may be reduced due to the use of the lower density drilling fluid.
It is also an advantage of this invention that due to the use of a lower density fluid, drill pipe differential sticking may be minimized. In addition, a lower filter cake thickness may be deposited upon the well bore wall, which may further reduce the probability of drill string sticking.